Good day ladies and gentlemen. Welcome to the TransCanada Corporation 2007 Third Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President of Investor Relations and Communications. Please go ahead, Mr. Moneta.

David Moneta - Vice President, Investor Relations and Communications

Great. Thanks very much. Good morning everyone. I'd like to take this opportunity to welcome you today. We are pleased to provide the investment community, the media and other interested parties with an opportunity to discuss our 2007 third quarter financial results and other developments concerning TransCanada.

With me today are Hal Kvisle, President and Chief Executive Officer; Greg Lohnes, Executive Vice President and Chief Financial Officer; Russ Girling, President of Pipelines; Alex Pourbaix, President of Energy and our Vice President and Controller, Glenn Menuz. Hal and Greg will begin today with some opening comments on our financial results and other developments pertaining to TransCanada. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com. It can be found in the investor section under the heading Conference Calls & Presentations.

Following Hal's and Greg's remarks, we will turn the call over to the conference coordinator for your questions. During the question and answer period, we'll take questions from the investment community first followed by the media. In order to provide everyone with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue.

Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations for your detailed financial models, Myles and I would be pleased to discuss them with you following the call.

Before Hal begins, I would like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.

Finally, I would also like to point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share and funds generated from operations. These measures do not have any standardized meaning prescribed by Generally Accepted Accounting Principles and are therefore considered to be non-GAAP measures. As a result, these measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide interested parties with additional information on the company's operating performance, liquidity and its ability to generate funds to finance its operations.

And with that, I will now turn the call over to Hal.

Harold N. Kvisle - President and Chief Executive Officer

Thank you, David. Good morning everyone. Thank you all for joining us today. I will take a few minutes to talk about recent developments in our business and I'll then turn the call over to our Chief Financial Officer, Greg Lohnes, who will review our financial results in more detail.

TransCanada's strong financial performance during the third quarter is a result of solid contributions for more long life legacy assets and growing cash flows and net income from newly acquired and developed assets such as the ANR pipeline system and the Bécancour power plant in Quebec.

We continue to grow our Pipelines and Energy business in a disciplined way with an unwavering commitment to large scale, long life infrastructure of the highest physical and financial quality. Through development of assets such as Bruce nuclear and the Keystone Pipeline system, we expect to generate strong financial results for our share holders over the longer term.

For the third quarter of 2007, TransCanada Corporation's net income from continuing operations was $324 million or $0.60 per share compared to $293 million or $0.60 per share in the third quarter of 2006.

Comparable earnings were $309 million or $0.57 per share compared to $243 million or $0.50 per share for the same period in '06, an increase of approximately 14% on a per share basis.

Funds generated from operations in third quarter 2007 were 6% higher at $702 million compared to $662 million for the same period in 2006.

TransCanada's Board of Directors declared a quarterly dividend of $0.34 per share for the quarter ended December 31, 2007 on the outstanding common shares. Shareholders that reinvest their dividends in additional common shares for the company through our dividend reinvestment and share purchase plan will continue to receive common shares from treasury at a 2% discount to the average market price.

You will hear more about our financials from Greg Lohnes.

First, I would like to make a few comments on some of the sizable developments over the last few months in our Pipeline and Energy businesses. First of all, on the Pipeline side, during the third quarter there was significant activity on the Keystone Oil Pipeline project. Today, we announced that based on strong industry support, we have entered into contracts or conditionally awarded approximately $3 billion for major materials and pipeline construction contracts. The Keystone team continues to secure land access agreements in preparation for the start of construction in the spring of 2008, about six months from now. Based on the increased size and scope of the project and the executed material and service contracts, the total capital cost of Keystone is expected to be approximately $5.2 billion.

Also on the Keystone front in September, we received NEB approval to construct and operate the Canadian portion of the Keystone Oil Pipeline. We intend to file an application with the National Energy Board in November for additional pumping facilities required to expand the Canadian section from a nominal capacity of approximately 435,000 barrels per day to 590,000 barrels per day. In total, Keystone has secured firm long-term contracts for a total of 495,000 barrels per day with an average contract duration of 18 years. Further to that, producers and refiners continue to express interest in contracting for additional long-term capacity on the pipeline. Keystone intends to hold a binding open season for remaining capacity by the end of this year.

Keystone will provide us with attractive returns and also give us another platform for growth. The support from committed shippers and ongoing expressions of interest for additional capacity clearly confirm the value of Keystone as a competitive way to link growing oil sands production to U.S. energy markets.

Finally, just a bit of background about the product Keystone will move. Keystone can move all types of crude oil. Keystone is designed to move the variety of crude oils determined by the industry and the same crude oil types that are moved today on all other crude oil export pipelines. The producing industry has determined and will continue to determine the specification of crude oil that can range from light crude to bitumen blended with synthetic crude or other types of crude oil. We move what our customers want and will continue to do that with the Keystone project.

Also in Pipelines, the Alberta Energy and Utilities Board provided approval in July to initiate negotiations on a three year settlement for our Alberta system. Negotiations with stakeholders on the Alberta system revenue requirement began in September 2007 and are ongoing. Our goal is to reach a settlement for a term of up to three years beginning January 1, 2008.

In the Northwest United States, Palomar Gas Transmission, a joint initiative by TransCanada and Northwest Natural Gas Company, was announced. This is a proposal to build a natural gas pipeline connecting to TransCanada's existing GTN system over to Northwest Natural's distribution system that would serve growing markets in Oregon, the Pacific Northwest and the Western U.S.

In October 2007, TransCanada's North Baja pipeline received a certificate from the U.S. Federal Energy Regulatory Commission to expand and modify its existing pipeline system. The modification will facilitate the import of regassified of LNG from Mexico into the California and Arizona markets.

Turning now to our Energy business. The scope of the Bruce A restart and refurbishment program that set out to deliver an additional 1500 megawatts was expanded. The expansion includes installing 480 new fuel channels in Unit 4, extending the operational life of Unit 4 from 2017 to 2036; that's 750 megawatts. The expansion is estimated to cost an additional $1 billion. In total, the restart and refurbishment program is expected to cost $5.25 billion, of which TransCanada's share is expected to be approximately $2.63 billion. Bruce is a very cost competitive long-term solution to help meet Ontario's power needs.

Also at Bruce, critical work continues on the Unit 1 and 2 restart. We recently completed replacement of all 8 steam generators and replaced the steam drums on Unit 2. This was a very significant milestone for that project.

Construction is also progressing on a number of power plant projects in Eastern Canada: the Halton Hills Generating Station, a 683 megawatts natural gas-fired power plant located at Halton Hills, Ontario and the 550 megawatt Portlands Energy Centre located near downtown Toronto in partnership with Ontario Power Generation. Construction continues on the 100 megawatt Anse á Valleau wind farm in Quebec and remains on schedule for completion by December of this year.

Cartier Wind received environmental approval from the Quebec government to build its proposed $170 million Carleton wind farm. This was the third project to be developed after Hydro-Québec's first wind energy call for tenders in 2004, all three of those projects developed by Cartier Wind in which TransCanada has a 62% ownership interest.

Also in the third quarter, TransCanada and the Saskatchewan government agreed to contribute up to $26 million each for the engineering design phase of a proposed polygeneration project near Regina. The Belle Plaine facility would have a very low greenhouse emission and use petroleum coke as feedstock for industrial uses and also generate 300 megawatts of electricity.

In closing, we are continuing to progress nicely on our portfolio of pipeline and energy opportunities that will create significant future value over the longer term for TransCanada shareholders.

I will now turn the call over to Greg Lohnes who will provide additional details on our financial results. Greg?

Thanks Hal and good morning everyone. As Hal mentioned, earlier today we released our third quarter results. Net income from continuing operations or net earnings for the third quarter were $324 million or $0.60 per share compared to $293 million or $0.60 per share for the same period last year. The third quarter 2007 net earnings included positive income tax adjustments of $15 million. Third quarter 2006 net earnings included a $50 million favorable income tax adjustment as well. Excluding these items, comparable earnings were $309 million or $0.57 per share for the third quarter 2007 compared to $243 million or $0.50 per share for the same period last year, an increase of approximately 14%. The quarter-over-quarter increase was due to increased contributions from both the Pipelines and Energy businesses.

I will briefly review the third quarter results for each of our segments, beginning with Pipelines. The Pipelines business generated comparable earnings of $163 million during the third quarter, an increase of $33 million over the same period in 2006. The increase was primarily due to the additional income earned from the acquisition of ANR, higher earnings from the Canadian Mainline and a higher earnings contribution from other pipelines. TransCanada completed the acquisition of ANR on February 22nd and included net earnings from that date. For the three and nine months ended September 30, 2007, ANR's net earning were $19 million and $69 million respectively, which is generally in line with our expectations.

The Canadian Mainline's net earnings increased $10 million for the third quarter when compared to the same period last year. The increase was primarily related to the higher common equity ratio, certain performance-based incentive arrangements and operations, maintenance and administrative cost savings under the five year toll settlement effective January 1, 2007 to December 31, 2011. Partially offsetting these increased earnings were a lower rate of return on common equity and a lower average investment base.

TransCanada's proportionate share of net earnings from other pipelines in the third quarter 2007 increased by $10 million when compared to the same period last year. The increase was primarily due to increased earnings from TC PipeLines, LP and lower project development costs. The earnings contribution from TC PipeLines, LP increased primarily due to TransCanada's increased partnership interest and TC PipeLines acquisition of a 46.45% interest in Great Lakes gas transmission. Project development costs decreased due to the timing of costs incurred relative to the same period last year and the capitalization of project costs related to the Keystone Pipeline extension in the third quarter 2007.

Net earnings also increased due to earnings from Tamazunchale which commenced operations in December 2006. These increases were partially offset by decreased earnings from Portland in comparison to third quarter '06 due to a bankruptcy settlement received in '06.

Next some comments on Energy. The Energy segment includes our Power and unregulated Natural Gas Storage operations as well as our business development initiatives in liquefied natural gas. Energy generated comparable earnings of $156 million in the third quarter compared to $123 million in the same period last year. The increase was primarily due to higher contributions from Western Power Operations, Eastern Power Operations and Natural Gas Storage. These increases were partially offset by lower contributions from Bruce Power and higher general administrative and support costs. Bruce Power contributed $64 million of pre-tax operating income in the third quarter compared to $72 million last year. The $8 million decrease was primarily due to higher post-employment benefit costs and other employee-related costs, higher costs associated with planned and unplanned outages and lower positive purchase price amortizations related to the expiry of power sales agreements. These impacts were partially offset by higher revenues resulting from higher realized prices. Bruce Power prices achieved during the third quarter 2007 were $55 per megawatt hour compared to $51 per megawatt hour in the third quarter 2006.

Looking forward, Bruce A Unit 3 is expected to have an outage lasting approximately one and a half months which begin in late third quarter. The overall plant availability percentage in 2007 is expected to be in the high 70s for the two Bruce A operating units and in the low 90s for the 4 Bruce B units. The capital cost of Bruce A's revised 4 Unit seven-year restart and refurbishment project is expected to total approximately $5.25 billion with TransCanada's share being approximately $2.6 billion. As of September 30th, Bruce A has incurred capital costs of $1.8 billion on the restart and refurbishment project.

Turning to Western Operations. Western Operations' operating income was $120 million in the third quarter compared to $84 million last year. The $36 million increase was primarily due to increased margins from the Alberta power purchase arrangements resulting from a combination of higher overall realized power prices and lower PPA costs, partially offset by lower volumes. Higher prices were realized despite a 3% decrease in average spot market prices in Alberta due to short-term contracting of prices higher than the spot market.

In the third quarter 2007, approximately 25% of Western Power sales volumes were sold into the spot market, consistent with the same period last year. To reduce our exposure to future spot market prices, Western Power operations has fixed price sales contracts to sell approximately 2600 gigawatt hours for the remainder of 2007 and 7600 gigawatt hours for 2008.

Finally in power, Eastern Operations' operating income in the third quarter was $52 million, an increase of $12 million compared to the third quarter of last year. The increase was primarily due to incremental income earned in 2007 from the start up of the 550 megawatt Bécancour cogeneration plant in September 2006 and payments received under the forward capacity market in New England partially offset by decreased generation from the TC Hydro facilities resulting from reduced water flows.

In the third quarter 2007, approximately 98% of Eastern Power sales volumes were sold under contract. To reduce our exposure to future spot market prices, Eastern Operation has fixed price sales contracts to sell approximately 4000 gigawatt hours for the remainder of 2007 and 12,400 gigawatt hours for 2008, although certain contracted volumes are dependent on customer usage levels.

Finally in the Energy segment, Natural Gas Storage operating income of $39 million in the third quarter increased $15 million compared to the same period last year. The increase was primarily due to incremental income earned in 2007 from the start up of the Edson facility in December 2006.

Turning to Corporate. Net earnings from Corporate in the third quarter 2007 were $5 million compared to $40 million in the same period last year. Excluding favorable income tax adjustments in the quarter, Corporate's comparable expenses were $10 million in each of the third quarters of 2007 and 2006. Higher financial charges, primarily as a result of financing ANR and Great Lakes acquisitions, were offset by gains on derivatives used to manage the company's exposure to foreign exchange rate fluctuations and the impact of positive tax rate differentials. We have natural hedges in place for our U.S. dollar asset and income positions primarily through using U.S. debt to finance our non-Canadian operations. In addition, we actively manage the remaining currency exposure using financial strategies and products within established policy limits. The combination of these longstanding programs reduces our exposure to changes in exchange rate.

Turning to the cash flow statement. Funds generated from operations were $702 million in the third quarter, an increase of $40 million or 6% when compared to the same period in 2006. This increase was mainly due to an increase in cash generated through earnings. Capital expenditures in the third quarter were approximately $364 million and related primarily to the ongoing development of greenfield projects such as Bruce A restart, Portlands Energy Centre, Halton Hills and Cartier Wind as well as growth and maintenance capital associated with the Canadian Mainline and the Alberta system.

Finally, our financial position remains strong. At the end of September, our balance sheet consisted of 55% debt, which included our proportionate share of joint venture debt, 4% junior subordinated notes, 1% preferred shares and 40% common equity. On July 5, 2007, TransCanada redeemed all of the outstanding $460 million 8.25% preferred securities due 2047. The redemption of these preferred securities was exercised in conjunction with the National Energy Board approved five-year settlement for the Canadian Mainline.

TransCanada and its subsidiaries have raised significant capital in 2007 in part to fund the acquisition of ANR and the remaining portion of Great Lakes. Of this, a considerable amount has been in the form of equity and equity-like instruments including the $1.725 billion raised in common shares issued in a public offering. In the second and third quarters 2007, TransCanada issued common shares from treasury under its dividend reinvestment and share purchase plan totaling $104 million. In April of this year, we issued $1 billion of junior subordinated notes. This hybrid security currently receives 50% equity credit from S&P and Moody's and 55% equity credit from DBRS. Also, TC PipeLines, LP raised $612 million in equity, of which 50% was acquired by TransCanada and 50% by third parties.

TransCanada will continue to manage the balance sheet in a prudent manner, consistent with maintaining our A credit rating. A strong balance sheet and our significant discretionary cash flow will continue to provide us with the financial flexibility to make future investments in our core businesses.

That concludes by prepared remarks. I'll now turn the call back to David for the question and answer period.

David Moneta - Vice President, Investor Relations and Communications

Great. Thanks Greg. Just a reminder, before I turn the call back over to the conference coordinator, we'll take questions from the financial community first and once we've completed that, we'll then turn it over to the media. Again, I ask that you limit yourself to two questions. If you have further questions, please reenter the queue. With that, I'll turn the call back over to the conference coordinator.

Question And Answer

Operator

Thank you. We'll now take questions from the financial analysts. [Operator Instructions]. The first question is from Matthew Akman from CIBC World Markets. Please go ahead.

Matthew Akman - CIBC World Markets

Thanks very much. Questions on the Keystone announcement from today, Hal. I'm just wondering if you can help us understand or clarify the significant cost increase in the project and how and whether TransCanada will earn a full return on that increase in the full expenditure.

Harold N. Kvisle - President and Chief Executive Officer

Yes, Matthew, we will earn a full return. All of these issues have been agreed contract with our shippers. The capital cost increase is partly due to an expanded system, moving more volume, more equipment and that sort of thing. It's also the result of capital cost increases in pipe and construction contractor rates. We have moved actively to nail down those costs, securing long-term supplies of steel for the pipe itself and entering into contracts with contractors for specific construction of the different sections of that pipeline. But under the terms of our arrangement with the shippers, we have the opportunity to come back and firm up the costs estimates and of course to expand the project to move more crude oil. And we have done all of those things over the last six or eight months, and the announcement today is really what we think the project will cost when it comes in and the volumes that we think will move under the current phase. We continue to wok on subsequent phases of the project and we look to increase volumes further. The demand is there and of course everybody is considering carefully the impact of the current royalty changes, but early indications that we have had are that volumes will need to move to market. There is a number of very big projects that are under way today. And regardless of a final analysis of the royalty changes, there will not be an issue about volumes adequate to fill the current contracted capacity and we believe further expansion capacity on Keystone.

Matthew Akman - CIBC World Markets

Okay. Just as a quick follow up then, when can we expect more details on TransCanada's share of this expenditure and return parameters and so forth as we go forward?

Harold N. Kvisle - President and Chief Executive Officer

Well, we continue to finalize the ownership arrangements with certain other parties that have the right to take a piece of it. We'll get to a final resolution on that, I would think, some time in the next three to six months, and I think that the rate of return issues and what not will become clearer over that time as well.

Matthew Akman - CIBC World Markets

Okay, thank you.

Harold N. Kvisle - President and Chief Executive Officer

Thanks Mathew.

Operator

Thank you. The next question is from Linda Ezergailis from TD Newcrest. Please go ahead.

Linda Ezergailis - TD Newcrest

Thank you. Perhaps just to follow up on Mathew's Keystone question, the cost increase, can you allocate that between the core system and then the expansion on the Keystone?

It's approximately about -- someone will correct me -- about 1.5 billion for the Cushing and then the balance would be, I guess, about 3.7 for the Patoka Wood River leg.

Linda Ezergailis - TD Newcrest

Great, thanks. And in terms of the Bruce Power system of units, the depreciation and amortization has jumped up $7 million to $43 million versus the prior run rate. Is that somehow related to this Unit 4 deal? Can you explain and what's going on there?

Glenn G. Menuz - Vice-President and Controller

Linda, it's Glenn Menuz here. No, the Unit 4 will only be depreciated once it gets in there. I think what you're seeing in there are just the timing of some items coming into service as well as some other minor adjustments in there. But again, just to note that those are 100% numbers and obviously our share would be smaller than that range.

Linda Ezergailis - TD Newcrest

Okay, but that's the new run rate that we should use?

Glenn G. Menuz - Vice-President and Controller

I'm not exactly sure about the details, but it's going to be in the ballpark.

Linda Ezergailis - TD Newcrest

Okay. And while we are on the subject of Bruce Power, perhaps you can let us know what the next major milestone would be the Bruce restart and is it still on time and on budget?

Alexander J. Pourbaix - President, Energy

Linda, it's Alex. We have now -- as Hal mentioned in his prepared remarks, I mean we have now installed all the steam generators in Unit 2 and we have now moved our heavy lift crane to Unit 1. So from my perspective anyway, I think there is really a couple of issues. It's going to be removing and replacing the steam drums and the steam generators in Unit 1. And we are now well into the process of removing the end fittings of the pressure tubes on the Unit 2 reactor; AECL is doing that. And those are, really from my perspective, the big events that are going on.

Linda Ezergailis - TD Newcrest

And so -- and that's on time and on budget versus your original estimate?

Alexander J. Pourbaix - President, Energy

Yes, we -- as I think I've said at the last conference call, I mean we are continuing with our view that this project is going to come in well within the ranges of return that we had talked about then, and we are very happy with the progress of the restart to date.

Linda Ezergailis - TD Newcrest

Okay. Thank you.

Alexander J. Pourbaix - President, Energy

Okay.

Operator

Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Robert Kwan - RBC Capital Markets

Great, thank you. Just on the Western Power side, the implied hedge price was in -- it looks like it was in the mid $80 per megawatt hour range. And that looks like it's a pick up from prior quarters. Is there something we can expect going forward just in terms of having seen the forward curve move out?

Alexander J. Pourbaix - President, Energy

Sorry, I missed -- could you repeat that question? I missed a bit of it at the end.

Robert Kwan - RBC Capital Markets

Sure. It just looks like the -- like you are selling in terms of the hedge prices moved up in Q3 to somewhere in the mid $80 per megawatt hour range. Is that something we can expect going forward just based on what we've seen in terms of the forward curve move up as well?

Alexander J. Pourbaix - President, Energy

Sorry, I understand the question. I think that's probably a little higher than we would expect particularly in Q4. Q3 always tends to be one of our highest price quarters. So that's probably a little slightly optimistic from my perspective.

Robert Kwan - RBC Capital Markets

Okay. And if you just look at say the year-over-year results, if I can remember correctly, you weren't able to capture a lot of the upside last year from the spike in power prices. Can you just -- how would you characterize say Q3 '06 versus Q3 '07 in terms of pricing and volumes and how you captured the opportunity?

Alexander J. Pourbaix - President, Energy

Sorry, I don't know if I would agree with that characterization. I thought we did a pretty good job of capturing the spike in the power prices. We obviously have a strategy of selling forward a relatively significant percentage of our output. But we've been quite pleased with our contracting practice, and I look at our contracted portfolio right now and I think it looks quite attractive.

Robert Kwan - RBC Capital Markets

Maybe, Alex, if I put it a different way, your earnings are up very significantly in the quarter.

Alexander J. Pourbaix - President, Energy

Yes.

Robert Kwan - RBC Capital Markets

Volumes are down. And how would you kind of characterize what was driving the big change then year-over-year given spot power prices were very similar? Was it just all the contracting strategy?

Alexander J. Pourbaix - President, Energy

I think so. I mean the Alberta market, particularly in July, was characterized by some very high prices, and I think it would be fair to say that we were well prepared to benefit from that volatility.

Robert Kwan - RBC Capital Markets

Okay. Great. Thank you.

Harold N. Kvisle - President and Chief Executive Officer

In part, Robert, it's Hal here, I'll just add to that. We see a pretty tight market in Alberta. And we are concerned firstly that the market structure is not allowing or inducing people to build more capacity, but at the same time we foresee these periods of tightness coming, and I think our power can do us a good job of getting a good rate of return out of that.

Robert Kwan - RBC Capital Markets

But Hal actually, to the extent that you're seeing or you're view being incremental tightness, is that going to change even just a little bit on the margin, your contracting strategy as you go forward?

Alexander J. Pourbaix - President, Energy

Yes, I mean we are certainly flexible with our contracting strategy. I mean we are very focused on maintaining TransCanada's credit rating and just the security instability of earnings. But at the same time, we are flexible when we see opportunities where we see a lot of opportunity for higher prices rather than lower prices. I think you will see that sort of 75, 50, 25 kind of contracting strategy vary accordingly.

Robert Kwan - RBC Capital Markets

Great. Thanks Alex.

Harold N. Kvisle - President and Chief Executive Officer

Thank you.

Operator

Thank you. The next question is from Sam Kanes from Scotia Capital. Please go ahead.

Sam Kanes - Scotia Capital

Good morning, Al. I am curious about the strategy with respect to your preliminary look at the Saskatchewan pet coke polygeneration unit. Watched for years as power study, study, study, then kill [ph], a project that sounds quite similar. I am wondering if you could elaborate on whether this is a, the only project you are looking at this kind. And Alberta obviously needs something like this as well and all over the U.S. there is a variety of different projects. Is it the same project? How much has it changed and what is the degree of interest from a TransCanada strategic point of view?

Harold N. Kvisle - President and Chief Executive Officer

Well I think Sam the big picture would be that we see firstly declining gas production out of Western Canada and we have seen increasing demand for natural gas at places like Fort McMurray. We look at the carbon dioxide agenda that's playing out and we recognize there has to be other forms of electricity generation that emit less CO2. We look at IGCC, integrated gasification combined cycle, as a very interesting way. But we also recognize that the technology is in the early stages and most of these projects have been characterized by dramatic cost overruns. We visited gasification facilities in Dakota, IGCC plants in Florida, we have done a lot of work with General Electric and Bechtel on the Saskatchewan project. We continue to look at two or three different opportunities here in Alberta both related to coal-fired power, perhaps using a gasification process but also looking at petroleum coke in the Fort McMurray and Fort Saskatchewan area. So we are looking at all these things. We think longer term, we have got a very significant supply of pet coke and coal obviously here in the West, and there will be demand for natural gas, whether it's produced natural or synthetic natural gas.

On the Saskatchewan project in particular, we have tried to be very astute about the way we go forward. We have put several million dollars into the project so far and we have said to the Government of Saskatchewan, given their involvement and the CO2 agenda, we are not prepared to continue putting money into this thing without some complementary contribution from them. And so that's basically the structure that we have landed on. And we continue to work with some very sophisticated parties in GE and others on how you move the technology forward and exactly what's it going to take. And I hear you on plans getting announced, a lot of hoopla and then these projects getting canceled as people figure out it's just too difficult and they are at too early a stage in the technology cycle. So we are going to proceed cautiously. We are not aggressively trying to get this plant built in a hurry. We want to continue to move forward, but we are going to make sure that we spend the necessary money upfront on technology and engineering and avoid the kind of multi-billion dollar mistakes that we have seen on some others.

Sam Kanes - Scotia Capital

Thank you.

Harold N. Kvisle - President and Chief Executive Officer

And Alex would to that.

Alexander J. Pourbaix - President, Energy

Yes, Sam, I might just make one comment on that. I think from our perspective, our polygen facility in Saskatchewan is actually quite a bit different from the oxy fuel facility that SaskPower was looking at. From our perspective, the polygen facility, I think power is just one of the off takes and it significantly benefits in its economics by the proximity to several other off takes in the region whereas the oxy fuel project that SaskPower was doing was really purely a powergen facility. And from our perspective, that technology was very, very in the experimental phase whereas the IGCC technology proposed to be used as a polygen facility is something that has been around for decades and is quite well understood.

Sam Kanes - Scotia Capital

Thank you for that. A quick follow up maybe to you, Alex. Now that Alberta has opened up the wind cap, if you may, and you've good success experience in Quebec, does that not make logical sense to extend out that way in the Alberta market?

Alexander J. Pourbaix - President, Energy

We have always followed wind and Alberta very closely. And obviously the cap that had been imposed really made it difficult to consider anything. Now that hard cap is gone, but I think practically the issue that remained is still the issue of transmission access to these wind opportunities in Alberta. So we continue to look at them, but I think Alberta continues to be challenged with a lack of transmission infrastructure and the costs associated with building transmission infrastructure to some of these isolated sites.

Sam Kanes - Scotia Capital

Okay. Thank you, Alex.

Operator

Thank you. The next question is from Bob Hastings from Canaccord Adams. Please go ahead.

Bob Hastings - Canaccord Adams

Hi, just a clarification from Alex on the transmission side. One of the things that you have been looking at I gather is Northern Lights, and does that impact to you at all and what are your plans on that these days?

Alexander J. Pourbaix - President, Energy

We have said for years that probably the most significant problem plaguing the Alberta power market is its relative lack of interconnectedness with surrounding jurisdictions, particularly the Pac Northwest. We think that right now there is a unique opportunity with Northern Lights to really do a couple of things. I mean number one, better connectivity between Northern Alberta and Southern Alberta, which is obviously a problem with the cancellation of the recent alternating [ph] project. But I think more fundamentally as we move to a CO2 constrained world, we see a lot of opportunity to connect wind in Southern Alberta, hydro in Northern Alberta, cogen in Northern Alberta to markets in the South.

Bob Hastings - Canaccord Adams

Okay. So with the cancellation or the delay in the alternating [ph] project, would you be able to -- are you looking at ways to propose other projects around that?

Alexander J. Pourbaix - President, Energy

Yes, we are not working at specifically competing with any project, with any AC project that might be contemplated sort of a north-south interconnect -- or strengthening project. I am just suggesting that in the longer term

Alberta will continue -- whether or not a north-south line -- AC line is built, Alberta is going to continue to need more transmission connectivity between the North and the South. And we think that our HVDC Northern Lights line could very much play a role in that longer term.

Bob Hastings - Canaccord Adams

Okay, thank you. And can I get a clarification on the Keystone project? You capitalized costs in there, and I wondered if you could tell us sort of what those were and whether there is any catch up in previous costs with maybe expense in other quarters?

No, there is no catch up. As we've disclosed in the past, we have capitalized -- we have disclosed our capitalized costs each quarter. I think what are you seeing this quarter with the jump in capital costs is really around pipe order and locking in some of these other contracts.

Bob Hastings - Canaccord Adams

Okay. Thank you very much.

Unidentified Company Representative

Thank you.

Operator

Thank you. The next question is from Karen Taylor from BMO Capital Markets. Please go ahead.

Karen Taylor - BMO Capital Markets

Thanks. I just have a couple of questions really quickly. Maybe David, if you've got the tax rates for Bruce and in the Gas Storage segment is my first question.

David Moneta - Vice President, Investor Relations and Communications

Yes, I haven't got them here handy. Karen, my recollection was we have used approximately 32, 33% on those two businesses, and I don't expect they would have changed.

Karen Taylor - BMO Capital Markets

Okay. And just a couple of other orco miracle [ph], how much was the adjustment to the TC PipeLine, LP contribution arising from the higher ownership? I am not sure I understood what that comment meant in the release.

David Moneta - Vice President, Investor Relations and Communications

Well I think there were two things there. One, obliviously, we are up from last year just -- the LP owning a share of Great Lakes here, a significant share of Great Lakes, we also own a more significant share of the piped LP. And in the laundry list of items, there was a small adjustment in there.

Karen Taylor - BMO Capital Markets

So are you talking less than $1 million or like non-material?

David Moneta - Vice President, Investor Relations and Communications

Not material. A couple or $3 million. I think it was about $3 million give -- or so Karen.

Karen Taylor - BMO Capital Markets

Okay. And we talk about foreign exchange rates in the commentary I guess, and maybe this is for Greg. Given all of the hedging ad natural offset with the debt position, what is the exposure of $0.01 change in the exchange rate?

I guess -- I mean you say without hedges. So we have our income offset by the interest on the debt. I'd say without hedges, there is about 100 to $130 million of exposure there, which would be about $1.3 million per cent [ph] change in the exchange rate, 1.3 net income. That's virtually all hedged with hedges that are rolling on a 12 month basis on a fourth quarter going forward basis. And therefore for right now, we have pretty much totally covered that exposure. As we go out looking forward of course, we are rolling these hedges forward and we are really deferring the impact of the change in exchange rate. Now that impact all shows up in corporate. The operating units are taking their hit as we go along when you look at the numbers from the operating units and then the hedge benefit shows up on the corporate side.

Karen Taylor - BMO Capital Markets

Right. So I just want to understand, because you can't really beat the trend with the series of rolling hedges, so if you put the hedges aside then, it's basically, a $0.01 move in exchange rate is $1.3 million in net income?

Okay. And just very lastly, we talked about capitalization of costs and potential delays on Cacouna. Can you tell me how much cash, or rather costs have been capitalized for Cacouna? And then can you please give us an update on the proposed in-service date of Broadwater?

Harold N. Kvisle - President and Chief Executive Officer

Okay, I will tackle the first question. We haven't capitalized any costs for Cocuna.

All right. Karen, we are still waiting for FERC environmental impact assessment, which we expect towards -- right now, we are expecting towards the end of the year and I don't think we have communicated any different date for the in-service.

Karen Taylor - BMO Capital Markets

So given the timeline for this particular approval, you wouldn't expect one or you just haven't announced one?

Harold N. Kvisle - President and Chief Executive Officer

Karen, it's Hal. It's interesting that we have got two challenges on almost all of these LNG projects, we and everybody else in the industry. First is getting regulatory approval to build the facility and the second is securing the supply of LNG.

Karen Taylor - BMO Capital Markets

Right.

Harold N. Kvisle - President and Chief Executive Officer

Our two projects are quite different in that regard. At Cacouna, we are working to bring down capital costs and to finalize LNG supply. And in the current supply demand environment, that's a major task, and we are working hard on that. At Broadwater, our partner of course is Shell, and Shell has more options for LNG supply, I believe, than any other company. So the issue at Broadwater, clearly, there is a great market, there is great market demand for that LNG coming in and we've aligned ourselves with what I consider to be the best possible supplier. So the issue at Broadwater is really one of getting environmental approvals and other approvals from the State of New York. The major approval is the environmental impact statement from FERC, and that we hope to get within the next few months and then we go on to secure whatever approvals we need from the state.

Karen Taylor - BMO Capital Markets

Has the state given you clearances under the Costal Zone Management Act?

Harold N. Kvisle - President and Chief Executive Officer

Sorry, has the state given us clearance on --

Karen Taylor - BMO Capital Markets

Under the Coastal Zone Management Act, which is really their environmental trump card, have they given you approval for the project on that basis?

Harold N. Kvisle - President and Chief Executive Officer

No, that's -- they don't address that question until they get the finding from FERC.

Karen Taylor - BMO Capital Markets

Okay. Thank you.

Harold N. Kvisle - President and Chief Executive Officer

Thanks Karen.

Operator

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

Andrew Kuske - Credit Suisse

Thank you. Good morning. Hal, in the previous comments you mentioned about the tightness in the Alberta power market and how you look at that in the future. I am just curious as to what your strategy is as far as your PPA exposure goes in Alberta. Because if we look at over time and we look at the tightness there, the market does look tight, but your PPAs roll off in 2017 and 2020. And if we look at the build time that's needed for a coal plant, it is considerable. So I am just wondering what are your thoughts at this stage on Alberta and how you approach your power strategy in Alberta.

Harold N. Kvisle - President and Chief Executive Officer

Well I will provide a quick comment and let Alex add to it. First of all, our PPAs do run off in that 2017, 2020 timeframe and we acknowledge that. And we also acknowledge your point about the long lead times, and not a week goes by that Alex or I don't speak to the Alberta government about the need to work now on plans to replace this generation when it reaches end of life. Not only do our PPAs run out in that timeframe, but it is not too long after that that quite a number of the coal units in Alberta start to reach the end of their useful life. And in fact some of them will be coming offline before 2017; not our units, but some of the others in the overall Alberta coal fleet. So we look at we look at a number of different opportunities here in Alberta. Certainly, coal gasification is one of them. We'd be quite nervous as a company about proceeding with a simple coal-fired generation facility, and we think you have to look at other technologies that enable the capture of CO2 if you are going to be using coal as the generation.

We also looking at -- we have obviously taken steps to develop our own gas-fired fleet, and that's a great way to generate electricity in Alberta other than we are not sure how expensive gas is going to be. And that's obviously something we worry about. We have looked at a number of large scale hydro projects. I'd underscore a comment Alex made earlier that really for people to invest significant money in merchant generation in Alberta, we need better connectiveness with major U.S. markets. You can't bring on 2 or 3000 megawatts in a new project and have that output stranded in Alberta. During the early years of a new plant you have got to have a safety valve to release that output into the larger Western North American market. So that's where we think transmissions a big part of it. We are aware that other people have looked at nuclear opportunities in Alberta. And with our partners of Bruce, we also look at those things. But obviously that's a complex step, there is a lot of technical issues. The building of a nuclear plant is not a simple thing, and we are doing our homework on that before we decide whether or not we would want to engage in that kind of generation build here in Alberta.

So there is many opportunities, but you are right, the planning horizon is long and we need to deal with this early on if we are going to keep the lights on in this province 10 years from now.

Andrew Kuske - Credit Suisse

Well I guess my overarching concern, and then that's all great color and commentary, but my overarching concern is when we get out to that period of time, there is a bit of an earnings cliff that you face if you didn't recontract the PPAs or have your own generation facilities assuming that the PPA of [ph] plant owners, those facilities just go away, which might or might not be a valid assumption.

Alexander J. Pourbaix - President, Energy

Andrew, it's Alex. I think that's a very valid point. I guess I would have a couple of responses to it. From our perspective in the short term, I mean we have to be worried about things like market our concentration. We are already at about 20% of this market. But long term, we absolutely consider one of our core competencies and competitive advantages our knowledge of and our position in the Alberta power market. So I think you can take it as a given that we are very active right now on assessing development opportunities in those range, as Hal said, from things as small as 100 megawatt wind farms up to 1500 megawatt major hydro projects in Northern Alberta. So I don't foresee a situation over the next 10 or 15 years where we don't continue to maintain a very significant power generation position in Alberta.

Andrew Kuske - Credit Suisse

And then if I may, I guess what's your view on the PPA plant owners' ability to life expand and then just extend contracts with them?

Alexander J. Pourbaix - President, Energy

I guess there is potentially that opportunity. At the time these PPAs were entered into, the terms were calculated, for all intents and purposes, to coincide with the end of life of the plants. Now I think realistically, our experience with coal plants tend to be that those -- they never go away, they just keep getting refurbished in one way or another. So I do expect there is life in those plants longer than the PPA life. But the issue, I think the big issue in Alberta and the big issue in Canada is going to be the CO2 costs associated with continuing to run those plants. And as Hal mentioned right now, it really is -- there is a great deal of uncertainty under the federal act, the plan as to what those costs of CO2 compliance are going to be. I think our view is very much that right now there is no viable technology to capture CO2 off the back end of those existing and relatively late in life coal plants. So I think there is going to be challenges in life extending them if we continue under the present federal plan that we have right now. I think if there is some opportunity to do that, I mean we are obliviously going to engage with the asset owners to see if there is an opportunity for us to continue with some form of entitlement under those plants.

Andrew Kuske - Credit Suisse

That's great. Thank you very much.

Harold N. Kvisle - President and Chief Executive Officer

Thanks Andrew.

Operator

Thank you. The next question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Daniel Shteyn - Desjardins Securities

Yes, good morning everyone. A couple of questions here. First, on the Alberta system negotiated settlement that is currently underway, I guess one of the things that you'll be looking at, and I believe you've already commented on, is the increase in the deemed equity ratio, up from 35%. I am just wondering if you can comment whether you are shooting for 40%, like you have gone on the Canadian Mainline and also if you believe that the likely outcome of the process will result in a fixed return for a couple of years or maintaining enough floating ROE.

Russell K. Girling - President, Pipelines

On your second question, it's too early to speculate where we might land with that negotiation. That discussion has just started. Our target at the end of the day is likely a number that looks like 40% with an appropriate corresponding return on equity that would get us what we would call a fair return. And that fair return will probably be in the neighborhood of 7% on a all in sort of return on capital basis. So you can sort of back [ph] calculate where we think the ROE needs to be. And so that's the nature of discussions consistent with the asks [ph] that we have made in the regulatory forums and the asks [ph] that we've made on Mainline. Now obviously, we didn't achieve all of that on the Mainline in the settlement, and the settlement includes other factors like performance incentives, cost incentives and those kinds of things. That's sort of what we'd be targeted for heading into a settlement.

Daniel Shteyn - Desjardins Securities

Okay, thank you. And for my follow-up question, I would like to just briefly touch on Bruce. I guess on page 9 of our press release here, there is an operating income number for 100% of Bruce for the three months at $204 million versus last year at 181 million. But TransCanada's proportionate share stays at 69 despite the increase in operating income, which could be attributed either to a decrease in your ownership percentage, which I do not believe to be the case or potentially a half a sentence comment that was made later on in page 10 saying lower positive purchase price amortization related to the expiring of power sales agreements. I wanted to see if you can shed a little light on the matter.

Glenn G. Menuz - Vice-President and Controller

Yes, Daniel, it's Glenn Menuz here. Just taking it sort of line by line, you are right that the 100% operating income is up this year, but our proportionate share is flat. What you are seeing there is just the difference or the ratio or the proportion between Bruce A and Bruce B. As you know, we own roughly 31.6% of Bruce B and about 48% of Bruce A. And as we mentioned in some of the narrative that Bruce did experience some planned and unplanned outages this quarter as well as costs. And they were just a little higher on the A side and we own more of that. So proportionately, we didn't reap as much as that positive variance. As far as the expiry of the sales contracts, where you are seeing that is in the line below that that's called adjustments, and these some of the historical or legacy contracts that we had acquired at the time of our original ownership and they've just rolled off. So we've handled those through our purchase price accounting. So it ends up just showing up in that adjustments line.

Daniel Shteyn - Desjardins Securities

And that the roll off is -- basically means that your pricing may go higher in going forward, is that --

Glenn G. Menuz - Vice-President and Controller

Yes, I think those -- what we had recorded on that was just the contracts at the time. And as far as where things go in the future will depend more on where the market prices go and contracting strategies.

Daniel Shteyn - Desjardins Securities

Okay, thank you.

Glenn G. Menuz - Vice-President and Controller

Okay, thank you.

Operator

Thank you. The next question is from Robert Kwan from RBC Capital Markets. Please go ahead.

Robert Kwan - RBC Capital Markets

Thanks. Just with the agreement that you have with the shippers on the higher capital costs on Keystone, was there anything either in the discussions or if some sort of within the agreement, either just a memorandum of understanding with respect to further extensions south Cushing into the Gulf Coast?

Russell K. Girling - President, Pipelines

There isn't any tie between the base Keystone project that goes to Cushing and what we are calling Keystone XL which goes to the Gulf Coast at the current time. Does that answer your question, Robert?

Robert Kwan - RBC Capital Markets

Yes, thanks Russ. But I guess just is there anything then in terms of Keystone XL, any update as to your timing in terms of potential open seasons or anything on that side?

Russell K. Girling - President, Pipelines

Nothing in terms of concrete dates for open season. We continue active discussions with both the refining community and the producing community. I would say that that -- those discussions have been delayed as a result of the royalty discussion here in Alberta where the producers in Alberta have been focused on the impact that that's going to have on their future capital investments and their future needs for export capacity from the province. So I would suspect once that sort of the dust settles and people understand what the impact on their investment profile is going to look like and timing, then we'll be able to get back to moving forward with Keystone XL discussions.

Robert Kwan - RBC Capital Markets

Great. Thanks Russ.

Operator

Thank you. The next question is from Shawn Burke from HSBC Securities. Please go ahead.

Shawn Burke - HSBC Securities

Yes, good morning. A couple of dead questions if I can. First of all, on the Keystone cost increase, particularly in the context of a lengthy list of projects that you have going on, can you tell us how the Keystone costs increase that you announced today is going to affect your external financing plans in '08 and '09? And then you talked about success in maintaining A level credit metrics. This year you were successful in doing a significant amount of new issue equity and hybrids in the U.S. markets for ANR and Great Lakes. Do you intend to do similar securities on the equity side going forward?

It's Greg Lohnes; I'll tackle those. Our balance sheet is in the strongest position it's ever been in. When we go to the equity markets, it's very rarely and it's for significant size as you saw us do in 2007. We are in a great spot right now moving forward. We have got lots of dept capacity. These projects come on over a period of years, and so the spend profile is spread out. We have got very strong cash flow. And as you have seen from the quarter, it's growing as we move forward. So we have got lots a capability on the debt side. We have also got our DRIP program operating. So as you saw, it was $104 million for two quarters. So, and we would expect that to stay about at that rate. So we are adding small amounts of equity at very reasonable cost to the company. And then we maintain our flexibility with our LP and other facilities and look at the opportunities we have around our entire asset portfolio as we always do when we prudently manage our portfolio.

Shawn Burke - HSBC Securities

Just in terms of your external financing, have you been -- have you focused on a particular CapEx budget dollar figure for '08 and '09 that you can share with us?

No, at this point, really, we are refining that. As Hal mentioned in the first quarter of '08 or later this year, we will be determining what percentage of Keystone we have, and that's really a huge driver for our CapEx. I would say generally our cash flow is committed over the next two or three years going forward with our substantial greenfield development program. And then we continue to look of course at acquisitions and other opportunities in the ordinary course of business.

Harold N. Kvisle - President and Chief Executive Officer

I'd just -- it's Hal here. I'd just add to that that if you go back to say the 1999, 2000 period, we were generating some thing like $700 million U.S in cash from operations for the full year. And in this current quarter, we generated something like $700 million U.S. in one quarter. Cash flow generation has grown very significantly within TransCanada and that has given us the ability to fund a much larger capital program. And to the extent that that larger capital program is directed at projects that bring subsequent increases in cash flow, we have a process that continues to strengthen the company and allow us to pursue bigger projects. So I would just point out don't overlook the internal cash flow and the growth in that when you think about how TransCanada can fund some of these significant projects.

Shawn Burke - HSBC Securities

Good enough. Thank you.

Harold N. Kvisle - President and Chief Executive Officer

Thank you.

Operator

Thank you. The next question is from Karen Taylor from BMO Capital Markets. Please go ahead.

Karen Taylor - BMO Capital Markets

Hi. I have got a follow-up question, just probably for Greg or Glenn Menuz. And on page 20 of the release, it talks about a $35 million after-tax realized gain from settled derivatives. Is that related to your interest rate hedges or power contracts? Can you give me some indication which segment that would in -- would be in and where whatever comes from?

Unidentified Company Representative

Karen, what I would suggest is we get back to you on that one.

Karen Taylor - BMO Capital Markets

Okay. And was there sort of timing issues related to the recognition of incentive gains on the Mainline? I think originally you had anticipated somewhere between $10 million and $15 million of incentive returns this year under the settlement.

Unidentified Company Representative

And I am not sure what you mean by timing. I would say that they are fairly constant throughout the year, Karen; if that's your question.

Karen Taylor - BMO Capital Markets

And then just lastly, I noticed that you filed an application on the Alberta system to recover a CO2 cost I think under bill two or bill three rather and in the amount of about $3 million to $4 million. Given that the federal government has carbon legislation on the table, does the current settlement agreement on the Mainline explicitly provide for carbon costs as a flows through?

Unidentified Company Representative

Yes.

Karen Taylor - BMO Capital Markets

Or do you have to have a filing?

Unidentified Company Representative

I don't know if we have to have a filing because I guess I suppose it depends on how things are sorted out at the time. But from a commercial perspective, we have the right to recover those costs under the agreement.

Karen Taylor - BMO Capital Markets

So you won't have to file then if --

Unidentified Company Representative

I don't know the answer to the regulatory question on whether we have to file or now. But commercially, we have agreed with our shippers that we can collect those costs.

Karen Taylor - BMO Capital Markets

Okay, thank you.

Harold N. Kvisle - President and Chief Executive Officer

And Karen, it's Hal. I'd just add that the bigger question is whether or not the costs to comply with carbon legislation on the Mainline will be significant or not. And there are a number of factors that give us a reasonable outlook for carbon compliance costs on the Mainline. The much bigger worry that we would have is how carbon costs will work in the power side of the business, and we are very focused on that.

Karen Taylor - BMO Capital Markets

Okay, thank you.

Unidentified Company Representative

Thanks.

Operator

Thank you. The next question is from Bob Hastings from Canaccord Adams. Please go ahead.

Bob Hastings - Canaccord Adams

Thank you. Just a different topic on the APG, you've funded a fair amount of money over to that, and I am just wondering what circumstances would trigger you writing that down as opposed to capitalizing it.

Harold N. Kvisle - President and Chief Executive Officer

Well I think our view, Bob, would be that the project continues to move forward. We continue to see the Mackenzie Pipeline as a viable project, and there is many thorny issues that need to be worked out and resolved. And we are working with the APG and with the producers in the Mackenzie to do that. Clearly, when the project gets to a point that we all conclude it's not going to go ahead, well then we have got a write-down issue to deal with on those costs. But at this particular point, we remain optimistic that we can pull all the details of this project together. It's not easy. The Mackenzie has been a work in progress for about three decades or more, and the challenges continue to be significant. But all parties are engaged and all parties are working on it and that's I guess about all I can say on it right now.

Bob Hastings - Canaccord Adams

Right. I am just looking at triggering [ph] plants where you might change your mind. And I don't think you'd say it's economic at this point of time, would you?

Harold N. Kvisle - President and Chief Executive Officer

Well, it depends on your outlook for gas prices. If you use today's gas price and the very highest cost estimates that have been generated for it, I think you'd have to question the economic liability. It's not clear that it would be an uneconomic. A lot of it also depends on production rates and how much other gas is available up there. But I think we look forward a little more optimistically because I don't think anybody would be more aware than us of the challenges of sustaining gas production in Alberta. We see roughly flat line production in Alberta and significant growth in demand, which sets the stage for higher price in Alberta. We frankly see a similar scenario unfolding all the way across North America with flat production at best over time. I see lately some people have come out with quite bullish forecasts of gas production growth in North America. I think those forecasts overlook the inexorable decline from our base producing sources in all parts of Canada and the U.S. So our scenario would be flat production at best out of existing areas of North America, setting the stage for higher prices and demand on both the LNG and Northern Gas sides. That would be the fundamental reason why we remain enthused by the project.

Bob Hastings - Canaccord Adams

Now certainly pricing has something to do with supply and demand over time, so I would agree with that. Thank you.

Harold N. Kvisle - President and Chief Executive Officer

We'll see where it goes. Thanks.

Operator

Thank you. The final question is from Daniel Shteyn from Desjardins Securities. Please go ahead.

Daniel Shteyn - Desjardins Securities

Yes. I had a follow-up question in relation with the cogeneration facility. I guess the couple of things that are out there that you've disclosed is that the timing is likely to be by 2013. Well, first of all, how do you see a financing structure for that particular project? How much of it, if it goes ahead, debt versus equity in terms of potential project economics and how long would a project like that take to build?

I guess in terms of financing, I guess what I would say is it's still very early days in that project. I think some fundamentals about it. Basically, 100% of -- that right now it is planned, the 100% of the off takes from that polygen plant would be sold under long-term contracts to very creditworthy counterparties. And that would be -- it would be very much a kind of plant that would be done on a tolling basis. So we as the owner and operator would not be sitting on any significant commodity exposure. We would have operating risk and capital risk. So obviously I would think that kind of plant would lend itself upon commissioning, would lend itself to a relatively high level of debt financing, probably something north of 50:50 notionally.

Daniel Shteyn - Desjardins Securities

Okay. And the economics would be, presumably, on the equity piece would be north of what you are getting, for instance, on your pipeline side or --

Not dissimilar from the kind of returns that we look for in our nuclear business. They are similar. I mean they are not dissimilar in the complexity of the projects.

Daniel Shteyn - Desjardins Securities

Okay, excellent. Thanks very much.

Harold N. Kvisle - President and Chief Executive Officer

Okay. Thank you, Daniel.

Operator

Thank you. We'll now take questions from the media. [Operator Instructions]. The first question is from John Hardine [ph] from the National Post. Please go ahead.

Unidentified Analyst

Good morning. On the cost increase for Keystone, I am trying to find a reference point or understand how much they have gone up percentage wise or again from what point.

Russell K. Girling - President, Pipelines

I think I'd give a shot at that is our original cost estimate in 2005 for the project as it's configured today would have been about $2.8 billion or $2.9 billion. So we have escalated by approximately $2 billion and a bit. So I guess that would be a number that would get you in that 70% kind of range.

Unidentified Analyst

Okay.

Russell K. Girling - President, Pipelines

From where we were originally. And as Hal pointed out earlier in the call, it's due to a number of factors. One, we have increased the scope and scale of the project, moving from 435,000 barrels a day to 600,000 barrels a day approximately. And then the escalation in both materials and labor costs would be the balance of that. And I think I would be consistent with the kind of escalations we have seen in other projects across North America. I think you were looking for benchmarks, you could look at some of the Alberta oil sands projects in terms of material changes in cost estimates from about that 2004, 2005 period to today.

Unidentified Analyst

Okay. And who is that, sorry?

Harold N. Kvisle - President and Chief Executive Officer

That was Ross Girling speaking.

Unidentified Analyst

Okay. Can I ask one follow up?

Harold N. Kvisle - President and Chief Executive Officer

Sure.

Unidentified Analyst

The issue of nuclear came up and just wondered if -- were you saying that you are looking at nuclear opportunities in Alberta?

Harold N. Kvisle - President and Chief Executive Officer

We are looking at nuclear opportunities in many parts of North America, and Alberta certainly one of them. We think Alberta is an interesting situation just because the long-term supply demand fundamentals are good in Alberta, there is certainly demand for power. We would not undertake something major like that unless Alberta was -- enjoyed much better interconnects with the bigger markets in other parts of North America. So you can't, we don't believe, drop several thousand megawatts of any kind of power, nuclear, river, hydro, world scale coal into a market like Alberta without seriously disrupting the market if you don't have the transmission connections to the bigger North American market. But we look at nuclear power opportunities in all parts of the country. Our main focus today is at Bruce and we have got an exceptionally competent nuclear development team at Bruce that has done a very good job of guiding the refurbishment of the Bruce A plant, which in many ways is similar to a complete newbuild. And we have confidence that that team would do a very good job of pursuing nuclear projects in Alberta if they make sense. What we don't know is whether it would be competitive with exotic forms of coal generation. We don't think simple coal-fired generation makes sense in Alberta going forward for CO2 reasons. But there are other coal gasification and projects like that that might make sense, and that's what nuclear has to compete with. So it's not a simple question. We are doing our detailed homework as always and looking at that opportunity as well as many others in different parts of North America.

Unidentified Analyst

Thanks very much.

Harold N. Kvisle - President and Chief Executive Officer

Thanks John.

Operator

Thank you. The next question is from Ian McKinnon from Bloomberg News. Please go ahead.

Ian McKinnon - Bloomberg News

Hi there. I have a question for Russ Girling and it's regarding Keystone, the base cost. Like checked some of our old stories and we talked about $2 billion, $2.1 billion. I am wondering if that $2.8 billion, $2.9 billion figure that you are using includes the extension to Cushing.

Russell K. Girling - President, Pipelines

That's correct. The original estimate -- of the Patoka Wood River leg was about 2.1 billion in 2005 dollars.

Ian McKinnon - Bloomberg News

Okay. So that brings me to my next question. If Cushing's now going to cost approximately $1.7 billion; that's basically double what it was a couple of years ago, does that mean you are seeing greater cost increase in the U.S. side than in Canada? I am just kind of curious on this point.

Russell K. Girling - President, Pipelines

No, it's related to, as I said, steel and materials and labor. And those changes are the same on both sides of the border, I would say. Actually, the closer you get to Alberta the higher the labor component of those costs are going to be. Materials such as pipe and valves and those kinds of things are going to be common no matter where you buy them. But I'd say labor is more extensive and more in sort of scarce supply the closer you get to the West.

Ian McKinnon - Bloomberg News

Okay. And then can you clarify like if you are saying pipe and labor is going up, what are we talking about? A third, 50%, any sort of clarity on that?

Russell K. Girling - President, Pipelines

I would say that our pipe costs are probably somewhere in the neighborhood of 50 to 60% higher than they were two years ago.

Ian McKinnon - Bloomberg News

Okay.

Harold N. Kvisle - President and Chief Executive Officer

And there is one other factor. You'll notice that all our estimates for this project are in U.S. dollars. And the most significant part of the capital cost is on the U.S. side. That's the bigger side, half of the project. But as the Canadian side goes up, the strengthening Canadian dollar adds another element to higher costs.

Ian McKinnon - Bloomberg News

Okay.

Harold N. Kvisle - President and Chief Executive Officer

So there are labor costs. I think the steel is generally priced in U.S. dollars and most of the major equipment is priced in U.S. dollars. But the Canadian contractors, as Russ pointed out, are increasingly expensive the closer you get to Alberta or in Alberta. And there is some significant construction on this project within Alberta. So the rising Canadian dollar also plays a role.

Ian McKinnon - Bloomberg News

Okay. And Hal, one follow-up question for. On Mackenzie Delta, can you give any color or comment on whether TransCanada's in negotiation or willing to assume leadership role and take over from Imperial, because certainly that's one of the thoughts that's been floating around?

Harold N. Kvisle - President and Chief Executive Officer

We are and we have been for several years part of the project. We are involved in the project; we are not an outsider trying to negotiate to get in. We are in the project. And all I would say the partners in the project are examining every alternative to come up with a toll for the Mackenzie producers that makes it attractive for them. They've got billions of dollars that they need to spend to develop the gas fields up in the Mackenzie Delta. And sometimes as people talk about the cost of the pipeline, it's overlooked that there is very significant expenditure to be made in the development of gas reserves and processing facilities and equipment up there. TransCanada's not involved in the development of gas reserves up there. So clearly, the producers are in the lead on that. I'd just say we are discussing a whole range of different things. TransCanada's always been willing to contribute as best we can. We have a lot of construction expertise in building pipelines. We have a lot of cold weather expertise and we have a very good working relationship with the producers and with the APG. We are all working together to try to bring this project to fruition, and I think that's all I would say at this point.

Ian McKinnon - Bloomberg News

Thank you.

Harold N. Kvisle - President and Chief Executive Officer

Thanks.

Operator

Thank you. [Operator Instructions]. The next question is from Scott Haggett from Reuters. Please go ahead.

Scott Haggett - Reuters

Hi. I wonder if you can refresh my memory --

David Moneta - Vice President, Investor Relations and Communications

I am sorry, Scott. We can't hear you very well. Could you just try that again?

Scott Haggett - Reuters

Hi, is that better?

David Moneta - Vice President, Investor Relations and Communications

Yes.

Scott Haggett - Reuters

Sorry about that. I am wondering if you can refresh my memory on the agreement with Conoco-Phillips and what the status of that is on Keystone.

Russell K. Girling - President, Pipelines

Conoco has the right to purchase a 50% equity interest in the Keystone pipeline. They haven't exercised that option yet, and we expect them to exercise it sometime probably before the first quarter of next year, exercise or not. They'd like to make a decision one way or another, so rough some time before the end of first quarter next year.

Scott Haggett - Reuters

And that will involve paying their share of costs after that -- incurred and forward, is that the --

Russell K. Girling - President, Pipelines

Exactly.

Scott Haggett - Reuters

Okay. And one more question, what effect do you see the higher price tag having on tolls to -- on the line?

Russell K. Girling - President, Pipelines

Well, obviously, it will proportionately increase the tolls. So the tolls will go up by -- in fact they have announced that the capital went up. When we look at sort of the competitiveness of the tolls relative to other options that the producers have to get to both the Patoka, Wood River area and the Cushing, with the increased capital costs, we are still landing at an all in cost that less than what we believe the competitive alternatives to be. All alternatives are experiencing these very similar cost increases. We are all ordering steel from exactly the same manufacturers and utilizing exactly the same contactors. So across the board, the costs have risen and tolls will go up. And given that we have a significant portion of our pipeline, it's a 2000 mile pipeline, about 6 or 700 miles of that is across the Prairies from Alberta to Winnipeg. That steel is already in the ground. We are converting one of our existing Mainline gas pipes to crude oil. So we are not experiencing a cost increase of the same magnitude for that. It's about basically one-third of the project. So our cost escalations are less than others cost escalations would be if you had to build sort of 100% from supply source to delivery source. So even with the cost increases, we are still very, very competitive, and our customers agree with that and obviously are very supportive of the project.

Scott Haggett - Reuters

All right. Thank you very much.

Harold N. Kvisle - President and Chief Executive Officer

Thanks Scott.

Operator

Thank you. There are no further questions registered at this time. I would now like to turn the meeting back over to Mr. Moneta.

David Moneta - Vice President, Investor Relations and Communications

Thank you and thanks to all of you for participating this morning. We appreciate your interest in TransCanada and we look forward to speaking to you again soon. Thanks.

Operator

Thank you. The conference has now ended. Please disconnect your lines at this time. Thank you for your participation and have a nice day.

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